Position monitoring system and method

ABSTRACT

An ultrasonic position sensing system is disclosed. In one embodiment, the system includes an ultrasonic sensor configured to monitor the position of a device. The system also includes ranging logic. The sensor is controlled by the logic to direct an ultrasonic pulse toward the device. The logic is configured to compute the transit time and the velocity of the ultrasonic pulse. Based on these parameters, the logic computes the path length between the sensor and the device, which corresponds to the location of the device relative to the location of the sensor. In further embodiments, the ultrasonic positioning system may include multiple sensors in communication with the ranging logic for monitoring multiple devices.

BACKGROUND

This section is intended to introduce the reader to various aspects ofart that may be related to various aspects of the presently describedembodiments. This discussion is believed to be helpful in providing thereader with background information to facilitate a better understandingof the various aspects of the present embodiments. Accordingly, itshould be understood that these statements are to be read in this light,and not as admissions of prior art.

In order to meet consumer and industrial demand for natural resources,companies often invest significant amounts of time and money insearching for and extracting oil, natural gas, and other subterraneanresources from the earth. Particularly, once a desired subterraneanresource is discovered, drilling and production systems are oftenemployed to access and extract the resource. These systems may belocated onshore or offshore depending on the location of a desiredresource. Such systems generally include a wellhead assembly throughwhich resources are extracted.

In the case of an offshore system, such a wellhead assembly may includeone or more subsea components that control drilling and/or extractionoperations. For instance, such components may include one or moreproduction trees (often referred to as “Christmas trees”), controlmodules, a blowout preventer system, and various casings, valves, fluidconduits, and the like, that generally facilitate the extraction ofresources from a well for transport to the surface. Some of thesecomponents may include sub-components or devices that are configured forlinear movement. For example, a blowout preventer system may includemultiple blowout preventers assembled in a stack-like arrangement. Eachof these blowout preventers may include one or more pistons that areconfigured to move in a linear direction when actuated. For instance, inthe case of a ram-type blowout preventer, opposing pistons may betranslated horizontally toward each other (e.g., via hydraulicactuation) to drive a corresponding pair of opposing rams toward thecenter of a wellbore. Other examples of linearly actuated devices thatmay be present in subsea equipment include various types of pressure orflow control devices, such as valves, connectors, and so forth.

Position monitoring (also referred to as ranging) with respect to suchlinear moving components has been an ongoing challenge for the industry,particularly with respect to devices that are deployed in subseaenvironments. Without an adequate position monitoring system, it isdifficult for operators to assess the position of a linearly actuatedcomponent or how far the component has translated in response to anactuation event. Moreover, due to the harsh environments in which subseaequipment is often operated, the ability to monitor the condition of thesubsea equipment is also useful. Having a reliable position monitoringsystem in place may provide for improved condition monitoring of subseaequipment. For example, position monitoring may be useful fordetermining whether or not a particular component exhibits an expectedbehavior in response to an actuation control input. In the absence ofreliable position information, condition monitoring metrics may relymore heavily on the relationship between time parameters and actuationparameters, which may be insufficient to accurately delineate normalizedcondition status.

Existing solutions for position monitoring have included the use ofelectromechanical position sensing devices in conjunction with linearlyactuated components. One example of an electromechanical positionsensing device is a linear variable differential transformer (LVDT).However, the use of electromechanical devices in position monitoring isnot without drawbacks. For instance, electromechanical devices, such asLVDTs, may be subject to a common-mode failure, as they are subject to alevel of mechanical degradation similar to the component beingmonitored. Further, the incorporation of electromechanical positionsensing devices into existing subsea equipment may require that existingequipment be redesigned and modified to accommodate theelectromechanical position sensing devices and associated components,which may be not only be costly and time consuming, but oftentimesimpractical.

SUMMARY

Certain aspects of some embodiments disclosed herein are set forthbelow. It should be understood that these aspects are presented merelyto provide the reader with a brief summary of certain forms theinvention might take and that these aspects are not intended to limitthe scope of the invention. Indeed, the invention may encompass avariety of aspects that may not be set forth below.

Embodiments of the present disclosure relate generally to an ultrasonicposition sensing system for monitoring the position of a componentconfigured for motion. In one embodiment, the position sensing systemincludes an ultrasonic position sensor and ranging logic that computesthe position of the component relative to the position of the sensor. Todetermine the component position, the ranging logic transmits anelectronic signal that is converted by a transducer within the sensorinto an acoustic signal in the form of an ultrasonic pulse, which isthen directed toward a surface of the moving component. When the pulseis reflected, a corresponding echo is received by the sensor, convertedback into an electronic signal, and transmitted back to the ranginglogic. The ranging logic determines several parameters to compute theposition of the component, including the velocity of the pulse as afunction of temperature and pressure and a fluid transit time of theultrasonic pulse. Thus, once travel time and velocity are known, theranging logic is able to determine the distance traveled by theultrasonic pulse, which corresponds to the position of the movingcomponent relative to the sensor.

Various refinements of the features noted above may exist in relation tovarious aspects of the present embodiments. Further features may also beincorporated in these various aspects as well. These refinements andadditional features may exist individually or in any combination. Forinstance, various features discussed below in relation to one or more ofthe illustrated embodiments may be incorporated into any of theabove-described aspects of the present disclosure alone or in anycombination. Again, the brief summary presented above is intended onlyto familiarize the reader with certain aspects and contexts of someembodiments without limitation to the claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of certain embodimentswill become better understood when the following detailed description isread with reference to the accompanying drawings in which likecharacters represent like parts throughout the drawings, wherein:

FIG. 1 is a block diagram depicting a subsea resource extraction systemin accordance with aspects of the present disclosure;

FIG. 2 is a block diagram that depicts a blowout preventer system thatis part of the resource extraction system of FIG. 1, wherein the blowoutpreventer system incorporates an ultrasonic position sensing system andhas multiple blowout preventers each having at least one ultrasonicposition sensing device in accordance with aspects of the presentdisclosure;

FIG. 3 is a more detailed partial cut-away perspective view of aram-type blowout preventer that may be part of the blowout preventersystem of FIG. 2;

FIG. 4 is a cross-sectional view showing an actuator assembly of theram-type blowout preventer of FIG. 3 having a piston in a retracted(open) position in accordance with aspects of the present disclosure;

FIG. 5 is a cross-sectional view showing the actuator assembly depictedin FIG. 4, but with the piston in an extended (closed) position;

FIG. 6 is a more detailed cross-sectional view showing an ultrasonicposition sensing device installed in the actuator assembly of theram-type blowout preventer shown in FIGS. 3 to 5, and being configuredto sense the position of the piston in accordance with aspects of thepresent disclosure;

FIG. 7 is a cross-sectional perspective view of the actuator assemblydepicted in FIGS. 4 and 5 that shows the ultrasonic position sensingdevice installed in the actuator assembly;

FIG. 8 is a flow chart depicting a process for determining a path lengthcorresponding to the position of a movable component using an ultrasonicposition sensing system in accordance with aspects of the presentdisclosure;

FIG. 9 is a cross-sectional view showing a portion of the actuatorassembly of the ram-type blowout preventer of FIGS. 4 and 5 thatincludes multiple ultrasonic position sensing devices in accordance withaspects of the present disclosure;

FIGS. 10 to 12 collectively show a transducer assembly that may be usedin an ultrasonic position sensing device in accordance with oneembodiment;

FIGS. 13 and 14 collectively show a transducer assembly that may be usedin an ultrasonic position sensing device in accordance with anotherembodiment;

FIG. 15 is a flow chart depicting a process by which the positionmonitoring techniques set forth herein are used to monitor the operationof a device and to trigger an alarm condition if abnormal behavior ofthe device is detected;

FIG. 16 shows an example of a graphical user interface element that maybe displayed for monitoring the operation of a device for which positioninformation is acquired using an ultrasonic position sensor inaccordance with aspects of the present disclosure;

FIG. 17 depicts an ultrasonic position sensing device that may beinstalled in a subsea device in accordance with a further embodiment;and

FIG. 18 is a cross-sectional perspective view showing the ultrasonicposition sensing device of FIG. 17 installed in the actuator assembly ofa blowout preventer in accordance with aspects of the presentdisclosure.

DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS

One or more specific embodiments of the present disclosure will bedescribed below. In an effort to provide a concise description of theseembodiments, all features of an actual implementation may not bedescribed in the specification. It should be appreciated that in thedevelopment of any such actual implementation, as in any engineering ordesign project, numerous implementation-specific decisions must be madeto achieve the developers' specific goals, such as compliance withsystem-related and business-related constraints, which may vary from oneimplementation to another. Moreover, it should be appreciated that sucha development effort might be complex and time consuming, but wouldnevertheless be a routine undertaking of design, fabrication, andmanufacture for those of ordinary skill having the benefit of thisdisclosure.

When introducing elements of various embodiments, the articles “a,”“an,” “the,” and “said” are intended to mean that there are one or moreof the elements. The terms “comprising,” “including,” and “having” areintended to be inclusive and mean that there may be additional elementsother than the listed elements. Moreover, any use of “top,” “bottom,”“above,” “below,” other directional terms, and variations of these termsis made for convenience, but does not require any particular orientationof the components.

Referring initially to FIG. 1, an exemplary resource extraction system10 is illustrated in accordance with an embodiment of the presentinvention. The system 10 is configured to facilitate the extraction of aresource, such as oil or natural gas, from a well 12. As shown, thesystem 10 includes a variety of equipment, such as surface equipment 14,riser equipment 16, and stack equipment 18, for extracting the resourcefrom the well 12 by way of a wellhead 20.

The system 10 may be used in a variety of drilling or extractionapplications. Further, while the system 10 is depicted as an offshore or“subsea” system, it will be appreciated that onshore systems are alsoavailable. In the depicted system 10, the surface equipment 14 ismounted to a drilling rig located above the surface of the water,whereas the stack equipment 18 is coupled to the wellhead 20 proximatethe sea floor. The surface equipment 14 and stack equipment 18 may becoupled to one another by way of the riser equipment 16.

As can be appreciated, the surface equipment 14 may include a variety ofdevices and systems, such as pumps, power supplies, cable and hosereels, control units, a diverter, a gimbal, a spider, and the like.Similarly, the riser equipment 16 may also include a variety ofcomponents, such as riser joints and connectors, fill valves, controlunits, and a pressure-temperature transducer, to name but a few. Theriser equipment 16 may facilitate the transport of extracted resources(e.g., oil and/or gas) to the surface equipment 14 from the stackequipment 18 and the well 12.

The stack equipment 18 may include a number of components, including ablowout preventer (BOP) system 22. The blowout preventer system 22,which is sometimes referred to as a blowout preventer stack, may includemultiple blowout preventers arranged in a stack-like configuration alonga portion of a wellbore of the system 10. The blowout preventers presentin this system 22 may include one or more ram-type blowout preventersand/or annular blowout preventers. In some embodiments, the system 22may include multiple blowout preventers, each being configured toperform different functions. For example, a blowout preventer system 22may include multiple ram-type blowout preventers, including thoseequipped with pipe rams, shear rams, and/or blind rams. The blowoutpreventer system 22 may also include blowout preventers of the same typeand which perform the same function for redundancy purposes, as well asadditional components, such as a wellhead connector, choke and killvalves and connectors, hydraulic accumulators, flex joints, controlpods, a lower marine riser package (LMRP) connector, and so forth.

The blowout preventer system 22 generally functions during operation ofthe resource extraction system 10 to regulate and/or monitor wellborepressure to help control the volume of fluid being extracted from thewell 12 via the wellhead 20. For instance, if well pressures aredetected as exceeding a safe threshold level during drilling or resourceextraction, which may indicate increased likelihood of a blowoutoccurring, one or more blowout preventers of the system 22 may beactuated via hydraulic control inputs to seal off the wellhead 20, thuscapping the well 12. By way of example, in the case of a ram-typeblowout preventer, each of a pair of opposing rams may be driven towardthe center of a wellbore using respective pistons actuated via hydrauliccontrol inputs, wherein each piston translates in a linear direction inresponse to the control input to move a respective ram. Such rams may befitted with packers that form an elastomeric seal, which may seal thewellhead 20 by severing the casing or drill pipe and effectively cap thewell 12. In the case of an annular blowout preventer, a piston may belinearly actuated to cause a packing unit to constrict around an objectdisposed in the wellbore, such as a drill string or casing.

Pistons used in blowout preventers represent an example of a linearlyactuated device or component. That is, such pistons may translate in alinear direction in response to a control input to drive anothercomponent, such as a ram (in ram-type blowout preventers) or a packingunit (in annular blowout preventers). As will be discussed in moredetail below with respect to FIG. 2, the blowout preventer system 22 ofthe presently disclosed embodiments includes a position sensing systemthat utilizes ultrasonic position sensing devices that enables theresource extraction system 10 to determine the linear position of alinearly actuated component or device being monitored. As used herein,the terms device and component may generally be used interchangeablywhen referring to an object having its position being monitored by theposition sensing system.

One aspect of position monitoring may refer to a determination of thelinear position (e.g., position along a linear path of movement) of adevice of interest with respect to the position of ultrasonic positionsensor. For example, in the case of a blowout preventer, the positionsensing system may utilize ultrasonic ranging to determine the linearposition of a piston within a blowout preventer. For example, in aram-type blowout preventer, the position of the piston may indicate howfar its corresponding ram has moved in response to actuation.Additionally, it should be understood that position monitoring, asimplemented by the position sensing system, may also be capable ofmonitoring the position of a stationary device or, to some extent, adevice that moves in a non-linear fashion (e.g., a circular path, curvedpath, etc.)

Other components of the stack equipment 18 of FIG. 1 include aproduction tree 24, commonly referred to as a “Christmas tree,” subseacontrol module 26, and subsea electronics module 28. The tree 24 mayinclude an arrangement of valves, and other components that control theflow of an extracted resource out of the well 12 and upward to the riserequipment 16 which in turn facilitates the transmission of the extractedresource upward to the surface equipment 14, as discussed above. In someembodiments, the tree 24 may also provide additional functions,including flow control, chemical injection functionality, and pressurerelief. By way of example only, the tree 24 may be a model of a subseaproduction tree manufactured by Cameron International Corporation ofHouston, Tex.

The subsea control module 26 may provide for electronic and/or hydrauliccontrol of the various components of the stack equipment 18, includingthe blowout preventer system 22. Further, the subsea electronic module28 may be designed to house various electronic components, such as suchas printed circuit boards containing logic to carry out one or morefunctions. For instance, with respect to the ultrasonic position sensingsystem, the subsea electronic module 28 may include ranging logicconfigured to calculate or otherwise determine the position of alinearly actuated device based on the pulse-echo response of anultrasonic position sensing device that monitors the linearly actuateddevice.

With these points in mind, FIG. 2 is a block diagram showing an exampleof a blowout preventer system 22 having multiple blowout preventers 32,including an annular blowout preventer 32 a and at least two ram-typeblowout preventers 32 b and 32 c. Of course, other embodiments mayutilize fewer or more blowout preventers 32. As discussed above,ram-type blowout preventers may be adapted for different functions basedon the type of ram blocks equipped. For instance, a ram-type blowoutpreventer may include pipe rams that are configured to close around apipe within a wellbore to restrict fluid flow within the annular conduitbetween the pipe and the wellbore but not within the pipe itself, shearrams configured to cut through a drill string or casing, or blind ramsconfigured to seal off a wellbore. Rams may also include blind shearrams that are configured to seal a wellbore even when occupied by adrill string or casing. Accordingly, the ram-type blowout preventers 32b and 32 c of FIG. 2 may be any one of the above-mentioned ram-typeblowout preventers, and may perform the same or different functions.

FIG. 2 additionally illustrates an ultrasonic position sensing system,depicted herein by way of the ultrasonic position sensing devices 34 andthe ranging logic 36, which is shown as being contained within thesubsea electronic module 28. As will be discussed in more detail below,an ultrasonic position sensing device 34 may be provided for eachlinearly actuated device in which position monitoring is desired. Forexample, with respect to each of the ram-type blowout preventers 32 band 32 c, at least two sensors 34 may be provided, each being configuredto sense the linear position of a respective one of a pair of opposingpistons. As generally depicted in FIG. 2, the sensors 34 may be locatedon opposite ends of the ram-type blowout preventers 32 b and 32 c. Theannular blowout preventer 32 a, which may include one piston for drivinga packing unit, also includes a corresponding sensor 34 for monitoringthe linear position of the piston.

Each position sensing device 34 includes an ultrasound transducerconfigured to convert an electrical signal received from ranging logic36 into an acoustic signal in the form of an ultrasonic pulse. The pulseis then transmitted by the position sensing device toward a surface ofthe linearly actuated device. The reflection of the ultrasonic pulse offa surface of the linearly actuated device, which may be referred to asan echo, is then directed back toward the position sensing device 34 andreceived by the transducer, converted back into an electrical signal,and transmitted back to the ranging logic 36. This path from the ranginglogic 36 to the sensor 34 and to the linearly actuated device and backmay be referred to as the signal path, which includes both theelectronic and acoustic paths.

The ranging logic 36 is configured to determine several parameters,including the total transit time along the signal path, the velocity ofthe ultrasound pulse, and any delay time in the signal path between thelogic 36 and the linearly actuated device. As will be discussed infurther detail below with respect to FIG. 8, based on the foregoingparameters, the ranging logic 36 calculates the path length along whichthe ultrasonic pulse travels to determine the linear position of thedevice (e.g., piston of a blowout preventer) being monitored. That is,the logic 36 determines the position of the linearly actuated devicewith respect to the position of the sensor 34 with which it isassociated. Further, while certain embodiments described herein relateto the use of the position monitoring system for assessing the linearposition of a particular component, the position monitoring system mayalso be used to determine the position of a component that is stationaryor moves in a non-linear manner with respect to the sensor 34.

As shown in FIG. 2, communication cables 38 may include wiring thatrelays signals between the ultrasonic position sensors 34 and theranging logic 36 in the subsea electronic module 28. The module 28 maybe disposed in a housing that is capable of withstanding the subseaenvironment. In other embodiments, the ranging logic 36 may bepositioned proximate to the linearly actuated device, such as on thehousing of a blowout preventer having a piston/ram that is beingmonitored using a respective sensor 34. Additionally, the ranging logic36 may also be distributed in some manner across the subsea electronicmodule 28 and on the housing of a subsea component containing thelinearly actuated device(s) of interest.

Collectively, the subsea control module 26 and electronic module 28 mayinclude communication circuitry that provides for communication witheach other, with various subsea components in the stack equipment 18,and with the surface equipment 14 and/or riser equipment 16. Forinstance, an umbilical containing one or more cables for relaying datamay transmit data from the stack equipment 18, subsea control module 26,and/or electronic module 28 to the surface equipment 14 and/or riseequipment 16. In one embodiment, such data may be transmitted inaccordance with a communication protocol, such as Modbus, CAN bus, orany other suitable wired or wireless communication protocol.Accordingly, position information acquired using the ultrasonic positionsensing system may be transmitted to the surface equipment 14, thusenabling an operator to monitor the operation of various subsea devicesmonitored by the sensors 34.

Referring now to FIG. 3, a partial cutaway perspective view of aram-type blowout preventer 32 that includes an ultrasonic positionsensor 34 is illustrated in accordance with one embodiment. Theillustrated ram-type blowout preventer 32 includes a body 42, bonnets44, actuator assemblies 46 and closing members 47 in the form of ramblocks. In the present embodiment, the rams 47 are shown as pipe rams byway of example only. As discussed above, other embodiments of theblowout preventer 32 may include shear rams, blind rams (sometimesreferred to as sealing rams), or blind shear rams. The body 42 includesa wellbore 48, ram cavity 50, and upper and lower bolted connections 52that may be used to assemble additional components above and below theblowout preventer 32, such as when the blowout preventer 32 is arrangedas part of a blowout preventer stack assembly.

The bonnets 44 are coupled to the body 42 by bonnet connectors 54. Theseconnectors 54 may allow for the bonnets 44 to be removed from the body42 of the blowout preventer 32 to provide access to the rams 47.Respective actuator assemblies 46 are mounted to the bonnets 44 atopposite ends of the body 42. As shown in FIG. 3, one of the actuatorassemblies 46 is shown in a partial cut-away view to expose and thusbetter illustrate the components therein. Thus, while the description ofthe actuator assemblies 46 may focus on the exposed actuator assembly ofFIG. 3, it should be understood that the unexposed actuator assembly 46on the opposite end of the body 42 is configured in the same manner. Forexample, the actuator assembly 46 includes a hydraulic piston 56disposed in a cylinder 58. In response to hydraulic control inputs, thepiston 56 may stroke in a linear direction within the cylinder 58, whichmay drive a corresponding ram 47 through the ram cavity 50, into and outof the wellbore 48.

As further shown in FIG. 3, the end of the cylinder 58 opposite thebonnet 44 is coupled to a head 60 by way of bolted connectors 62. In oneembodiment, an ultrasonic position sensor 34 may be installed in thehead 60 of each actuator assembly 46 to provide for linear positionmonitoring of the pistons 56 within their respective cylinders 58. Forexample, if the pistons 56 are actuated to drive the rams 47 to at leastpartially seal the wellbore 48, the use of the ultrasonic positionsensors 34 in conjunction with the ranging logic 36 may enable anoperator to monitor the movement of the pistons 56 and rams 47 and todetermine whether they are responding to the actuation event (e.g.,hydraulic control input) in an expected manner.

FIGS. 4 and 5 provide cross-sectional views showing one of the actuatorassemblies 46 of FIG. 3 in more detail. As shown, the actuator assembly46 is mounted to the bonnet 44 and coupled to a ram 47. In theillustrated embodiment, the ram 47 is shown as being a pipe ram with thedistal end of the ram 47 (i.e., closest to the wellbore 48) including apacker 68 that forms a seal around a pipe disposed within the wellbore48 when both rams 47 are extended from their respective ram cavities 50into the wellbore 48. Of course, as discussed above, other types of rams47 may include shear rams and blind rams.

In addition to the cylinder 58 containing the piston 56, the actuatorassembly 46 also includes a piston rod 70, the head 60, a sliding sleeve76, and a locking rod 78. The piston 56 includes a main piston body 80and a flange 82. The body 80 and flange 82 portions of the piston 56 mayinclude one or more seals, referred to by reference numbers 84 and 86,respectively. As shown in FIGS. 4 and 5, the body seal(s) 84circumferentially surround the piston body 80 while sealingly engagingthe inner wall of the cylinder 58. Similarly, the flange seal(s) 86circumferentially surround the piston flange 82 while sealingly engagingthe inner wall of the cylinder 58.

The engagement of body seal 84 and flange seal 86 with cylinder 58divides the interior of the cylinder 58 into three hydraulicallyisolated chambers: an extend chamber 88, a slack fluid chamber 94, and aretract chamber 98. An extend port 90 provides hydraulic communicationwith the extend chamber 88, which is formed between the head 60 and theflange seal 86. Similarly, a slack fluid port 96 provides hydrauliccommunication with the slack fluid chamber 94, which is formed in anannular region defined by the cylinder 58 and piston 56 between the bodyseal(s) 84 and flange seal(s) 86. Further, a retract port 100 providesfluid communication with a retract chamber 98, which is formed in anannular region defined by the cylinder 58 and piston 56 between the bodyseal(s) 84 and the bonnet 44.

In operation, the extend chamber 88 and the retract chamber 98 may be influid communication with a hydraulic fluid supply (not shown in FIG. 4or 5) regulated by a control system. In some embodiments, hydraulicfluid expelled from the extend chamber 88 and retract chamber 98 may berecycled into the hydraulic fluid supply or may be vented to thesurrounding environment. The slack fluid chamber 94 may bepressure-balanced with the surrounding environment such that fluidpressure within the slack chamber 94 does not resist the movement of thepiston 56 when actuated. In certain embodiments, the slack fluid chamber94 may be left open to the surrounding environment (e.g., sea water) ormay be coupled to a pressure compensation system that maintains balancedpressure within the slack fluid chamber 94.

With respect to FIG. 4, the actuator assembly 46 is shown in a fullyretracted position in which the piston 56 is disposed against the head60. This is sometimes referred to as the open position. When anactuation input is provided, such as via hydraulic controls, pressurizedhydraulic fluid is supplied through the extend port 90. This actuatesthe assembly 46 and causes the piston 56 to stroke, i.e., move in alinear direction, away from the head 60 toward the bonnet 44. As thepiston 56 moves toward the bonnet 44, the hydraulic fluid provided viathe extend port 90 enters the extend chamber 88. At the same time, fluidwithin the retract chamber 98, which may also include pressurizedhydraulic fluid, is expelled through the retract port 100, and fluidwithin the slack fluid chamber 94 is expelled through the slack fluidport 96. Fluid expelled from the slack fluid chamber 94 and retractchamber 98 during operation may be retained in a reservoir or, in somecases, ejected to the surrounding environment. As discussed above, theslack fluid chamber 94 may be open to the environment in someembodiments. For example, the fluid that enters and leaves the slackfluid chamber 94 in such an embodiment may be sea water in the case of asubsea installation.

Accordingly, as hydraulic fluid is supplied to the extend chamber 88,the piston 56 will continue to move in a linear direction towards thebonnet 44 until the piston 56 makes contact with the bonnet 44. This isshown in FIG. 5, which illustrates the actuator assembly 46 in a fullyextended position (sometimes referred to as the closed position).Although actuator assembly 46 is actuated by hydraulic pressure, manyapplications may also include a mechanical lock in order to maintain theposition of the ram 47, such as in situations where there is a loss ofhydraulic pressure. In order to positively lock the piston 56, and thusthe ram 47, in position, the sliding sleeve 76 is rotationally fixedrelative to the piston 56 and threadably engaged with a locking rod 78that is rotatably coupled to the head 60. The sliding sleeve 76 movesaxially relative to the locking rod 78 when the locking rod 78 isrotated, thereby locking the position of the piston 56 and ram 47.

When the piston 56 is actuated from an initially retracted position, asshown in FIG. 4, and begins to translate linearly away from the head 60towards the bonnet 44, the distance 104 (FIG. 6) between the head 60 andthe piston 56 continues to increase until the piston 56 reaches the endof its stroke, as shown in FIG. 5, i.e., the body 80 of the piston 56has made contact with the bonnet 44. The ultrasonic position sensor 34may be provided in the head 60 of the actuator assembly 46 to enableposition monitoring of the piston 56. The sensor 34 may be configured totransmit an ultrasonic pulse and receive a corresponding echo due to thereflection of that pulse off a surface of the piston 56. As will bediscussed in more detail below, the time that elapses between thetransmission of the pulse and the receipt of the corresponding echo maybe used by the ranging logic to determine the distance that pulsetraveled, and thus determine the linear position of the piston 56. Inmost cases, the device of interest may actually be the ram 47. However,since the ram 47 is driven by the piston 56, by knowing the linearposition of the piston 56, one is able to deduce how far the ram 47 hastraveled.

Referring now to FIG. 6, a more detailed cross-sectional view isprovided that illustrates an ultrasonic position sensor 34 in accordancewith one embodiment. Particularly, the sensor 34 is shown as beinginstalled in the head 60 of the actuator assembly 46 depicted in FIGS. 4and 5 and configured to direct ultrasonic pulses toward the piston 56.In the illustrated embodiment, the head 60 includes a recess 108configured to receive the sensor 34. The sensor 34 includes a housing110, an ultrasound transducer module 112, a temperature sensing device114 (shown in FIG. 6 as a resistance temperature detector (RTD)), and atransducer window 116. In certain embodiments, the transducer 112 may beof a model of an ultrasound transducer module manufactured by CameronInternational Corporation. The temperature sensing device 114 may be adiscrete component within the housing 110 or may be embedded as part ofthe transducer module 112, as shown in FIG. 6. In the presentembodiment, an opening 118 is also provided and may extend from therecess 108 through the opposite side of the head 60 to allow for thepassage of wiring between the sensor 34 and ranging logic 36.

The sensor 34 may be secured within the recess using any suitablemechanism. For instance, in one embodiment, both the recess 108 and thesensor housing 110 may be threaded and generally cylindrical in shape.Accordingly, the sensor 34 may be installed in the head 60 by simplyrotating the sensor housing 110 into the recess 108, thus allowing therespective threads to engage one another. In other embodiments, thesensor 34 may be secured in the recess 108 using an adhesive,connectors, or any other suitable technique. Overall, this provides fora relatively simple installation of the sensor 34 without requiringsignificant and/or complex redesign of existing subsea equipment.

To monitor the linear position of the piston 56 during operation, theultrasonic position sensor 34 may intermittently transmit an ultrasonicpulse 122. The pulse 122 may originate from the transducer 112 andpropagate through the window 116 and into the extend chamber 88, whichmay be filled with pressurized hydraulic fluid 120 as the piston 56 isactuated. The window 116 may include a high compressive strength plasticmaterial having acoustic impedance properties that are similar toliquid. This allows for the transmitted pulse 122 to leave the sensorhousing 110 while experiencing relatively little acoustic impedance. Byway of example only, the window 116 may formed using a polyetherimidematerial, such as ULTEM™, available from SABIC of Saudi Arabia, organicpolymer thermoplastic materials, such as polyether ether ketone (PEEK),or a polyimide-based plastic, such as Vespel™, available from E.I. duPont de Nemours and Company of Wilmington, Del. The housing 110 may bemanufactured using a metal material, such as steel or titanium, or maybe formed using one of the aforementioned plastic materials, or using acombination of metal and plastic materials.

After propagating through the window 116, the pulse 122 then travels thedistance 104 between the head 60 and the piston 56 through the hydraulicfluid 120. Upon impacting the piston 56, the pulse 122 is reflected inthe form of a corresponding echo 124. The transducer 112 receives theecho 124 as it propagates back toward the sensor 34 through thehydraulic fluid 120 and the window 116. The transducer 112 may operateat any suitable frequency, such as between approximately 200 kilohertzand 5.0 megahertz. In one embodiment, the transducer 112 is configuredto operate at a frequency of approximately 1.6 megahertz. Further,though not expressly shown in FIG. 6, the sensor 34 may include wiringthat may be routed through the opening 118, which may have a diameter orwidth that is less than that of the recess 108. Referring briefly backto FIG. 2, this wiring may represent the wiring 38 that provides forcommunication between the sensors 34 and the ranging logic 36.

While the recess 108 is shown in FIG. 6 as having a width (e.g., adiameter in the case of a circular recess) that is greater than that ofthe opening 118, in one embodiment, the recess 108 may be an openingthat extends all the way through the end cap 60. That is, the opening118 and the recess 108 may have the same width. In such an embodiment,the sensor housing 110 may be configured to extend through the end cap60. Also, in such an embodiment, wiring from the transducer module 112and/or the RTD 114 may form a connector coupled to the housing 110,wherein the connector is configured to electronically connect wiringwithin the sensor 34 to the ranging logic 36. For instance, such aconnector may be accessible from outside the cylinder 58 of the blowoutpreventer 32 and may be coupled to the ranging logic using one or moresuitable cables. This embodiment also allows for the ultrasound sensingdevice 34 to be installed from the outside of the blowout preventer 32or any other component in which it is to be installed, which obviatesthe need for any disassembly of the end cap 60 from the body of theblowout preventer 32 during installation. For instance, where the recess108 extends all the way through the end cap 60 and includes threads thatengage corresponding threads on the sensor 34, the sensor 34 may beinstalled from the outside by rotating the sensor assembly 110 into therecess 108 from the outside of the end cap 60 until the threads securelyengage one another.

As will be discussed in more detail below with respect to FIG. 8, theranging logic 36 may obtain or otherwise determine several parameterswhich are used to compute the path length along which the ultrasonicpulse 122 traveled prior to being reflected. This path length maycorrespond to the distance 104, which may enable an operator todetermine the linear position of a particular device, such as the piston56 in this example. The parameters obtained and/or determined by theranging logic include a computed velocity of sound (VOS) through a fluidas a function of temperature and pressure, a delay time, and a signalpath transit time. For example, the temperature parameter (e.g., thetemperature within the extend chamber 88) may be measured using thetemperature sensing device 114. The pressure parameter (e.g., thepressure within the extend chamber 88) may be provided to the ranginglogic 36 as an expected pressure value or, in other embodiments, may bemeasured pressure information provided to the ranging logic 36 by one ormore pressure sensing devices.

The delay time may represent non-fluid delays present in the signal pathwhich, as discussed above, includes the entire path (both electrical andacoustic portions) between the ranging logic 36 and the monitoreddevice. For instance, the presence of the window 116 and the wiring 38may introduce non-fluid delays. By subtracting out the delay time fromthe total transit time and dividing the result by two, the fluid transittime of the pulse 122 (or of its corresponding echo 124) may bedetermined. Accordingly, once the velocity of the ultrasonic pulse/echothrough the hydraulic fluid 120 and the fluid transit time are known,the path length between the head 60 and the piston 56 may be calculatedby the ranging logic 36, thus providing the linear position of thepiston 56. By knowing the linear position of the piston 56, the system10 can determine how far the ram 47 has traveled. In some embodiments,the fluid 120 need not necessarily be a liquid. For instance, the fluid120 may include a gas or a gas mixture, such as air.

In the present example, the ultrasonic position sensor 34 is used tomonitor the linear position of a piston in a blowout preventer of asubsea resource extraction system 10. Accordingly, the sensor 34 may bedesigned to be durable enough to withstand harsh environmentalconditions often associated with subsea operation. In one embodiment,the sensor housing 110, in which the sensor 34 is disposed, may bemanufactured using titanium, stainless steel, or any other suitable typeof metal, alloy, or super-alloy, and may be capable of operating atpressures of between approximately 14 pounds per square inch (PSI) to14,000 PSI. For example, the window 116 of the sensor housing 110 maywithstand loads of up to 14,000 PSI. The sensor 34 may also be capableof withstanding operating temperatures of between 0 to 100 degreesCelsius.

As shown in FIG. 6, the sensor 34 may be recessed within the recess 38by a distance shown by reference number 125. This distance 125 may beselected based at least partially upon certain properties of the window116, such as thickness and sound velocity characteristics, to compensatefor signal reverberation within the medium of the window 116. Thisreverberation is due to resonating properties of the window 116. Forexample, when the ultrasonic pulse 122 is transmitted from the sensor34, a portion of the signal 122 may reverberate within the window 116before dissipating. The amount of time that it takes for thisreverberation to dissipate may constitute what is sometimes referred toas a signal dead band. If an echo (e.g., 124) arrives at the sensor 34within this signal dead band, the sensor 34 may be unable to acquire anaccurate measurement due to interference from the ongoing signalreverberation within the window 116. This is generally most problematicwhen the target device, here the piston 56, is very close to the head 60(e.g., near or at the open position shown in FIG. 4), such that theelapsed time for the echo 124 to return to the sensor 34 falls withinthe dead band. Accordingly, recessing the sensor 34 by a distance 125within the recess 108 may compensate for the dead band effects, thusallowing the sensor 34 accurately acquire measurements for generally anyposition of the piston 56 within the cylinder 58.

The distance 125 may be selected as a function of the thickness of thewindow and its resonance properties. For instance, a plastic material,such as ULTEM™ or PEEK may have resonating properties in which anultrasonic signal reverberates within the window 116 for approximatelytwo round trips before dissipating. Thus, in this example, the goal inselecting the distance 125 is that the earliest time at which an echo124 reflected from the piston 56 returns to the sensor is outside of thesignal dead band time, with the most extreme case being when the piston56 is in the open position. Additionally, it should be noted that theplastic materials discussed above generally have lower resonatingproperties when compared to that of certain other materials,particularly metals such as steel. By comparison, in a sensor where theultrasonic pulse 122 is transmitted through a metal material, likesteel, the ultrasonic signal 122 may reverberate for approximately tenor more round trips within the steel before dissipating. This may resultin a longer dead band, which may require a greater distance 125 whencompared to that of a sensor 34 that uses a lower-resonating plasticmaterial of similar thickness, such as ULTEM™.

FIG. 7 is a more detailed perspective cross-sectional view that showsthe actuator assembly 46 of a ram-type blowout preventer 32 similar tothat described above in FIGS. 3 to 5, with the actuator assembly 46having an ultrasonic position sensor 34 installed in the head 60 via therecess 108. In this illustrated embodiment, the blowout preventer 32 maybe a dual-ram blowout preventer that includes two rams on each side of awellbore. Each ram on a particular side may be driven by a respectivepiston 56 within a cylinder 58 of an actuator assembly 46 coupled to thebody of the blowout preventer 32. For instance, in FIG. 7, the cylinder58 may house one piston 56 while the adjacent cylinder 58′ may houseanother piston (not visible in FIG. 7). Accordingly, the actuatorassembly 46 corresponding to the adjacent cylinder 58′ may also includea similarly configured ultrasonic position sensor 34.

FIG. 7 also depicts a handle 128 that may be engaged to rotate thelocking rod 78 to lock an extended piston 56 into the extended position.For example, the handle 128 may be engaged and operated by a remotelyoperated vehicle (ROV) or a manned underwater vehicle, such as asubmarine. Moreover, FIG. 7 also shows an embodiment in which at leastpart of the ranging logic 36 is located on the housing of the blowoutpreventer rather than being centralized within the subsea electronicmodule 28, as is shown in FIG. 2. For example, ranging logic 36 may bedistributed across multiple components, with portions of the logic 36being housed in a subsea enclosure, referred to herein as a ranging unit126, and affixed or otherwise secured to the housing of a component,here the head 60 of a blowout preventer 32. In this arrangement, allranging units 126 collectively make up the ranging logic 36, and eachranging unit 126 is configured receive input parameters and computeposition information for a linearly actuated device being monitored by arespective sensor 34.

Thus, in FIG. 7, the two ranging units 126 shown may correspond to thesensors 34 that monitor piston movement within the cylinders 58 and 58′.For instance, wiring extending through the opening 118 may connect eachsensor 34 to its respective ranging unit 126. Further, each ranging unit126 may be configured to communicate position information to the subseacontrol module 26 and/or subsea electronic module 28, which may thenrelay the information to the surface. Moreover, while the embodimentdescribed above shows the sensor 34 as being installed in the head 60,other embodiments may include a sensor 34 installed on the piston 56itself. Thus, in such embodiments, the ranging logic 36 may determinethe linear position of the piston 56 relative to the location of thehead 60 or some other point or reference.

Having generally described the operation of the sensor 34 above, aprocess 130 by which the ranging logic 36 may compute the linearposition of a monitored device is now described in further detail withreference to FIG. 8. Generally, the linear position of a device ofinterest (e.g., a piston/ram of a blowout preventer), may be determinedusing the following equation:d=VOS×t _(fluid),  (Eq. 1)wherein VOS represents the velocity of the ultrasonic pulse emitted bythe sensor 34 through a given medium (such as hydraulic fluid within theextend chamber 88) and t_(fluid) represents the one-way fluid transittime of the ultrasonic pulse (or its corresponding reflection), whichmay be equivalent to the total transit time in one direction along thesignal path with non-fluid delays removed. These parameters are thenused to determine the distance d across which the ultrasonic pulsetravels from the sensor 34 to the device of interest, thus enabling oneto determine the linear position of the device relative to the positionof the sensor 34.

As discussed above, VOS may be determined as a function of pressure andtemperature. For instance, in one embodiment, VOS may be computed inaccordance with Wayne Wilson's equation for the velocity of sound indistilled water as a function of temperature and pressure, as publishedin the Journal of the Acoustic Society of America, Vol. 31, No. 8, 1959.This equation is provided below:

$\begin{matrix}{{{V\; O\; S} = {\begin{bmatrix}A_{0} & A_{1} & A_{2} & A_{3} & A_{4}\end{bmatrix} \times \begin{bmatrix}1 \\T \\T^{2} \\T^{3} \\T^{4}\end{bmatrix}}},} & \left( {{{Eq}.\mspace{14mu} 2}a} \right)\end{matrix}$wherein T represents temperature in Celsius and A_(n) representscoefficients for computing the speed of sound, wherein the coefficientsA_(n) are calculated as a function of pressure, as shown below:

$\begin{matrix}{\begin{bmatrix}A_{0} & A_{1} & A_{2} & A_{3} & A_{4}\end{bmatrix} = {\begin{bmatrix}a_{0} & a_{1} & a_{2} & a_{3} \\b_{0} & b_{1} & b_{2} & b_{3} \\c_{0} & c_{1} & c_{2} & c_{3} \\d_{0} & d_{1} & d_{2} & d_{3} \\e_{0} & e_{1} & e_{2} & e_{3}\end{bmatrix} \times \begin{bmatrix}1 \\P \\P^{2} \\P^{3}\end{bmatrix}}} & \left( {{{Eq}.\mspace{14mu} 2}b} \right)\end{matrix}$Here, P represents pressure in bar and a_(n), b_(n), c_(n), d_(n), ande_(n) all represent additional sub-coefficients for computing soundvelocity. Thus, by substituting Equation 2b into Equation 2a, VOS may becalculated as follows:

$\begin{matrix}{{{V\; O\; S} = {\left( {\begin{bmatrix}a_{0} & a_{1} & a_{2} & a_{3} \\b_{0} & b_{1} & b_{2} & b_{3} \\c_{0} & c_{1} & c_{2} & c_{3} \\d_{0} & d_{1} & d_{2} & d_{3} \\e_{0} & e_{1} & e_{2} & e_{3}\end{bmatrix} \times \begin{bmatrix}1 \\P \\P^{2} \\P^{3}\end{bmatrix}} \right) \times \begin{bmatrix}1 \\T \\T^{2} \\T^{3} \\T^{4}\end{bmatrix}}},} & \left( {{{Eq}.\mspace{14mu} 2}c} \right)\end{matrix}$Equation 2c may be written into expanded form as:VOS=A ₀ +A ₁ T+A ₂ T ² +A ₃ T ³ +A ₄ T ⁴,  (Eq. 2d)wherein:A ₀ =a ₀ +a ₁ P+a ₂ P ² +a ₃ P ³A ₁ =b ₀ +b ₁ P+b ₂ P ² +b ₃ P ³A ₂ =c ₀ +c ₁ P+c ₂ P ² +c ₃ P ³A ₃ =d ₀ +d ₁ P+d ₂ P ² +d ₃ P ³A ₄ =e ₀ +e ₁ P+e ₂ P ² +e ₃ P ³

When applied to determine the velocity of sound through distilled waterunder a known pressure and temperature, the following coefficients maybe used in Wilson's sound velocity equation (Equations 2a-2d above):A ₀=1402.859+1.050469e ⁻² P+1.633786e ⁻⁷ P ²−3.889257e ⁻¹² P ³A ₁=5.023859+6.138077e ⁻⁵ P−1.080177e ⁻⁸ P ²+2.477679e ⁻¹³ P ³A ₂=−5.690577e ⁻²−1.071154e ⁻⁶ P+2.215786e ⁻¹⁰ P ²−5.088886e ⁻¹⁵ P ³A ₃=2.884942e ⁻⁴+1.582394e ⁻⁸ P−2.420956e ⁻¹² P ²+5.086237e ⁻¹⁷ P ³A ₄=−8.238863e ⁻⁷−6.839540e ⁻¹¹ P+9.711687e ⁻¹⁵ P ²−1.845198e ⁻¹⁹ P ³The computed values for the coefficients A_(n) may then be substitutedinto Equation 2d above to obtain the velocity of sound through distilledwater at a pressure and temperature represented by P and T,respectively.

As can be appreciated, the steps described above for determining VOS maycorrespond to steps 132 and 138 of the process 130 depicted in FIG. 8.For instance, at step 132, a temperature value (T) 134 and pressurevalue (P) 136 are acquired. As discussed above, the temperature valuemay be obtained using the temperature sensing device 114 of theultrasonic position sensor 34, while pressure may be supplied to theranging logic 36 as an expected or measured value (e.g., measured by apressure sensing device on the blowout preventer or other subseaequipment). In some embodiments, the temperature may also be provided tothe ranging logic 36 as an expected value rather than being a measuredvalue provided by the temperature sensing device 114. Once theseparameters are determined at step 132, the ranging logic 36 may computethe velocity of sound 140 in accordance with Wilson's equation at step138.

It should further be noted that the specific example of the numericalcoefficients provided above correspond to the properties of distilledwater. Nevertheless, these coefficients may provide for a relativelyaccurate calculation sound velocity through hydraulic fluids that arelargely based upon water (e.g., 99% water-based hydraulic fluids).Additionally, the numerical coefficients above may also be adjusted toaccount for any differences in the properties of distilled water and awater-based hydraulic fluid to further improve the accuracy of the soundvelocity calculation.

The other parameters used by the ranging logic to determine the distanced from Equation 1 include the total transit time of the ultrasonicsignal, including any non-fluid portions of the signal path (e.g.,window 116, wiring 38), and a non-fluid delay time corresponding todelays that non-fluid portions of the signal path contribute. Once thetotal transit time and non-fluid delay times are known, the fluidtransit time in one direction (e.g., that of either the pulse or theecho) is determined as follows:

$\begin{matrix}{{t_{fluid} = \frac{t_{total} - \tau}{2}},} & \left( {{Eq}.\mspace{14mu} 3} \right)\end{matrix}$wherein t_(total) represents the total transit time of both theelectronic and acoustic signals along the signal path, i.e., from theranging logic 36, along wiring 38 to the transducer 112, through thewindow 116, through a fluid medium (e.g., hydraulic fluid 120) in onedirection toward a device of interest, and back through each of thesecomponents following the reflection of the pulse. Accordingly, non-fluidcomponents in this signal path, which may include the window 116 andwiring 38 introduce some amount of delay, represented above in Equation3 as τ. Thus, the fluid transit time in one direction (e.g., either thepulse from the sensor to the device or interest or the echo from thedevice back to the sensor) is determined by removing the non-fluid delayτ from the total transit time, t_(total), and dividing the result bytwo, wherein the division by two gives a time value corresponding to thefluid transit time in one direction (rather than a round-trip time).

The total transit time, t_(total), may be determined via pulse-echo pathprocessing performed by the ranging logic 36. For instance, the ranginglogic 136 may determine the amount of time that elapses between sendinga signal that causes the pulse and receiving a signal resulting from thecorresponding echo. This is represented by step 142 of the process 130,which produces the total transit time (t_(total)) 144. With respect tothe non-fluid delay, each non-fluid component within the signal path mayintroduce a respective delay that may be expressed as follows:

$\begin{matrix}{{\tau_{{non} - {fluid\_ component}} = {2 \times \frac{L}{C}}},} & \left( {{Eq}.\mspace{14mu} 4} \right)\end{matrix}$wherein L represents the length of the portion of the signal paththrough the non-fluid component and C represents the velocity of thesignal through the non-fluid component. The result is multiplied by twoto account for the non-fluid delay in both the outgoing path and returnpath. By way of example only, assuming that the wiring 38 has a lengthof approximately 6 meters and that signal velocity through the wiring 38is approximately 1.4*10⁸ meters/second, the non-fluid delay contributedby the wiring (τ_(wire)) approximately 0.0857 microsecond (μs).Similarly, assuming that the window 116 of the sensor 34 has a thicknessof approximately 15.74 millimeters and allows for the ultrasonic pulseto traverse it at a velocity of approximately 2424 meters/second, thenon-fluid delay contributed by the window 116 (τ_(window)) isapproximately 13.0724 μs.

These non-fluid delay components (τ_(wire) and τ_(window)) are thensummed to obtain the total non-fluid delay time τ, which is representedby step 146 of the process 130 in FIG. 8. For instance, wire length andvelocity characteristics 148 and transducer window length and velocitycharacteristics 150 are provided to step 146. Using the expression setforth above in Equation 4, the ranging logic may compute the totalnon-fluid delay time (τ) 152 based on the parameters 148 and 150.

Thereafter, step 154 of the process 130 provides for the computation ofthe path length 156 between the sensor 34 and the linearly actuateddevice using the calculated sound velocity (VOS) 140, total pulse-echotransit time 144 along the signal path, and the non-fluid delay time152. Using Equation 3, the fluid transit time in one direction may becalculated as half the total transit time 144 less the non-fluid delaytime 152. Accordingly, once the fluid transit time is known, the pathlength 156 may be computed in accordance with Equation 1. When appliedto the examples described above with regard to a blowout preventer, thepath length 156 may represent linear position information regarding howfar a piston, and thus its corresponding ram, has moved in response toan actuation input.

The path length result 156 of FIG. 8 generally yields a measurement ofhow far the piston is relative to the window 116 of the sensor 34. Aswill be appreciated, for even further accuracy in some embodiments, thecalculated path length 156 may be further reduced by the distance bywhich the sensor 34 is recessed within the head 60 (e.g., distance 125of FIG. 6) to give a measurement of distance of the piston with respectto the inside wall (e.g., forming part of extend chamber 88) of the head60.

As noted above, in an embodiment where a hydraulic fluid used to actuatea device is not distilled water or substantially water-based, thecoefficients used in Equations 2a-2d above may be adjusted, such as viaempirical testing, to provide accurate sound velocity results whenultrasonic signals are transmitted through non-water fluids or thosethat are not substantially water-based. In another embodiment, ratherthan relying on Equations 2a-2d for the calculation of sound velocity, acombination of multiple sensors 34 may be used to determine the positionof a device of interest, with at least one sensor being directed towardsthe device of interest and another sensor being directed to a generallyconstant reference point. In such an embodiment, these sensors may bereferred to as a measuring sensor and a reference sensor, respectively.

An example of such an embodiment is shown in FIG. 9. Specifically, FIG.9 shows an embodiment of the above-described ram-type blowout preventer32 in which a piston 56 is actuated using a hydraulic fluid that is notwater or substantially water-based, such as an oil-based hydraulicfluid. Here, to determine the position of the piston 56, sensors 34 aand 34 b are provided in the cylinder 58, with the sensor 34 a being ameasuring sensor and the sensor 34 b being a reference sensor. Thesensor 34 a is oriented and configured like the sensor 34 shown in FIG.6 to measure the distance 172 (d₂) between the head 60 and the piston56. The sensor 34 b is identical to the sensor 34 a, but is oriented tomeasure the distance 170 (d₁) between the inside wall of the cylinder 58and the shaft 80 of the piston 56. As can be appreciated, the distance170 is generally constant except for periods when the piston 56 is in oralmost in the closed position (e.g., when the flange portion 82 of thepiston 56 enters the line of sight of the sensor 34 b). However,excluding such periods, the distance 170 measured by the sensor 34 is aknown distance d₁. According, the velocity of sound through thehydraulic fluid in slack fluid chamber 94 may be determined as follows:

$\begin{matrix}{{{V\; O\; S} = \frac{2 \times d_{1}}{t_{1{\_ fluid}}}},} & \left( {{Eq}.\mspace{14mu} 5} \right)\end{matrix}$wherein VOS represents the sound velocity over the known distance d₁ andt₁ _(—) _(fluid) represents the round-trip fluid transit time of anultrasonic signal from the sensor 34 b to the shaft 82 and back. As canbe appreciated, the fluid transit time t₁ _(—) _(fluid) may becalculated in a manner similar that described above, i.e., determiningthe total transit time and removing non-fluid delays (e.g., wiringdelays, window-imparted delays).

When the sound velocity VOS calculated using Equation 5 above is known,the distance 172 may be calculated as follows:

$\begin{matrix}{{d_{2} = \frac{V\; O\; S \times t_{2{\_ fluid}}}{2}},} & \left( {{Eq}.\mspace{14mu} 6} \right)\end{matrix}$Here, t₂ _(—) _(fluid) represents the round-trip fluid transit time ofan ultrasonic pulse (and its corresponding echo) emitted by the sensor34 a, which may again be calculated by measuring the round-trip totaltransit time along the signal path of the sensor 34 a and removingnon-fluid delays (e.g., wiring delays, window-imparted delays). Thedivision by a factor of two results in a one-way fluid transit timewhich, when multiplied by the known VOS value from Equation 5, providesthe distance d₂ corresponding to the path length between the sensor 34 band the piston 56. As discussed above, any distance by which the sensor34 b is recessed may be subtracted from the path length (d₂) todetermine the distance of the piston 56 from the head 60 of the cylinder58.

As can be appreciated, while the velocity of sound through a fluid mayvary as pressure and/or temperature characteristics change, in a subseaapplication utilizing the ram-type blowout preventer 32, temperature andpressure characteristics are generally not expected to vary greatlywithin short amounts of time. Additionally, ranging logic 36 may beconfigured detect when the piston flange 82 is in the line of sight ofthe sensor 34 b and to discard measurements for VOS acquired when thepiston 56 is in such a position. In this situation, most recent VOSvalues from prior to the piston flange 82 impeding the sensor's 34 bline of sight may be used in determining the path length d₂ as thepiston 56 nears the closed position. In the present embodiment, thesensors 34 a and 34 b are oriented such that they take measurements indirections that are perpendicular to one another.

As further shown in FIG. 9, the cylinder 58 may include the sensor 34 cpositioned within the inside wall 175 at the end of the cylinder 58opposite the head 58, i.e., the end that the flange 82 contacts when thepiston 56 is actuated to the closed position. This sensor 34 c may beused instead of or in addition to the sensor 34 a for assessing theposition of the piston 56. For instance, the distance 174 (d₃) betweenthe sensor 34 c and the flange 82 of the piston 56 may be determinedusing the known distance 170 (d₁). For instance, similar to thecalculation of d₂ by Equation 6 above, the distance d₃ may be calculatedas follows:

$\begin{matrix}{{d_{3} = \frac{V\; O\; S \times t_{3{\_ fluid}}}{2}},} & \left( {{Eq}.\mspace{14mu} 7} \right)\end{matrix}$Thus, the distance d₃ indicates generally how far the piston 56 is withrespect to the sensor 34 c on the inside wall 175. Moreover, in thisexample, the distance of the piston with respect to the head 60 may alsobe calculated by adding a known width 176 of the piston flange 82 to thecalculated distance d₃, and subtracting the result from the length ofthe cylinder 58, as measured from the head 60 to the inside wall 175.Further, some embodiments may include both sensors 34 a and 34 c,wherein the results obtained using each respective sensor may provide adegree of redundancy (e.g., if one sensor fails) or may be comparedagainst one another for validation purposes.

The position calculation algorithms described above may be implementedusing suitably configured hardware and/or software in the form ofencoded computer instructions stored on one or more tangiblemachine-readable media. In a software implementation, the software mayadditionally provide a graphical user interface that may displayinformation for presentation to a human operator. For instance, positionmeasurements acquired by the ultrasonic position sensing system may bedisplayed on a monitor of a workstation located at the surface of theresource extraction system 10 or at a remote location. The software mayalso be configured to save data logs for monitoring device positions(e.g., the position of rams) over time. Moreover, in the event that anaccurate measurement cannot be obtained, the software may provide for avisual and/or audible alarm to alert an operator. In some embodiments, avirtual (e.g., part of the software graphical user interface) orhardware-based (e.g., a component of a workstation) oscilloscope may beprovided for displaying the ultrasonic waveform that is transmitted andreceived. An example of such a user interface will be described in moredetail below with respect to FIG. 16. In a further embodiment, signalstacking may be used to some extent to improve signal-to-noise ratio.

As discussed above with reference to FIG. 6, each ultrasonic positionsensor 34 includes a transducer 112. One embodiment of the transducer112 is shown in more detail in FIGS. 10 to 12. Specifically, FIGS. 10and 11 show assembled and exploded perspective views, respectively, ofthe transducer 112, and FIG. 12 shows a cross-sectional view of thetransducer 112.

The transducer 112 includes the above-described window 116, as well as acasing 180, piezoelectric material 182, positive lead 184, negative lead186. The transducer 112 also includes the above-described resistancetemperature detector (RTD) for acquiring temperature data, and may be atwo-wire or four-wire RTD. As best shown in FIG. 10, the positive lead184, negative lead 186, and RTD 114 extend outward from the rear end(e.g., the end opposite the window 116) of the transducer 112. Whenassembled within a device, such as the head 60 of a blowout preventer32, portions of the positive lead 184, negative lead 186, and RTD 114may extend through the opening 118 (FIG. 6). The casing 180 generallyencloses the components of the transducer 112 and may be designed to fitwithin the sensor housing 110, as shown in FIG. 6. In one embodiment,the casing 180 may be formed using the same high compressive strengthplastic material as the window 116, such as ULTEM™, PEEK, or Vespel™. Inother embodiments, the casing 180 may be formed using a metal material,such as steel, titanium, or alloys thereof. The piezoelectric material182 may be formed using a crystal or ceramic material. For example, inone embodiment, the piezoelectric material 182 may include leadzirconate titanate (PZT).

Another embodiment of the transducer 112 is illustrated in FIGS. 13 and14. Specifically, FIGS. 13 and 14 show assembled and explodedperspective views, respectively, of the transducer 112. Here, thetransducer 112 includes the window 112 and RTD 114, as well as a casing190, piezoelectric material 192, load cylinder 194, cap 196, positive198 and negative 200 leads, and epoxy potting 202. The casing 190, loadcylinder 194, and cap 196 may be formed using high compressive plasticor a metal material, such as steel. The piezoelectric material 192 mayinclude PZT. Further, in this embodiment, the window 116 may include ahigh compressive plastic, such as ULTEM™, PEEK, or Vespel™, or may beformed as a wear plate using aluminum oxide (alumina). In someembodiments, the window 116 may include an alumina wear plate interposedbetween a plastic window and the piezoelectric material 192. Due to theimpedance, density, and velocity characteristics of alumina with respectto sound, such an embodiment may allow for acoustic energy to betransmitted through an alumina wear plate and into a plastic window withreduced distortion, provided that the dimensions and thickness of such awear plate are selected accordingly.

Referring to FIG. 15, a process 208 for operating of a system thatincludes an ultrasonic ranging system (e.g., system 36) for monitoringthe position of certain devices is illustrated in accordance with anembodiment. As shown, the process 208 begins at step 210 where a systeminput is received. The input may represent a command to move a devicewithin the system to a desired position. For instance, in the context ofa subsea system, the input may represent a command to close or open aram of a blowout preventer, wherein the closed or open positionrepresents the desired position. The system may actuate (e.g., hydraulicactuation) the device in accordance with the received input to cause thedevice to move to the desired position.

As the device (e.g., ram) moves toward the desired position, one or moreassociate ultrasonic sensors 34 may provide position information to thesystem, as shown at step 212. The expectation is that the device beingactuated will move to the desired position at the conclusion of theactuation process. Decision logic 214 determines if abnormal systembehavior is detected. In this context, abnormal behavior may be any typeof movement (or lack of movement) that deviates from an expectedbehavior. For instance, if the device being actuated is a ram that failsto attain a closed position in response to a command to close the ram,the process 208 may trigger an alarm to indicate to the system that theram cannot close, as indicated at step 216. Similarly, if the ram failsto open in response to a command to actuate the ram to an open position,the system may also trigger the alarm. The alarm may include audioand/or visual indicators. Returning to decision logic 214, if the devicedoes reach the desired position, no alarm is triggered and the systemcontinues normal operation, as indicated at step 218. While the cause ofalarm conditions may vary, this process 208 provides a mechanism thatreadily alerts the system (and thus those in charge of operating thesystem) in the event of any abnormal behavior.

Accordingly, an operator may assess the situation based on the alarmand, if necessary, temporarily shut down the system for maintenance orrepair procedures. As will be appreciated, the embodiments of theranging system described herein may operate based on closed-loop oropen-loop control. Further, the system may provide for not only controlof the position of a particular device, but also the velocity at whichthe device is actuated when being translated to a desired position. Forinstance, in the case of a ram in a blowout preventer being actuatedfrom an open to a closed position, the ram's movement may be controlledsuch that it initially moves relatively quickly and slows down as itapproaches a pipe within the wellbore.

FIG. 16 shows an example of a graphical user interface (GUI) element 220that may be part of the ranging system 36. This GUI element 220 may bedisplayed on, for example, a workstation located at the surface of theresource extraction system 10 or at a remote location in communicationwith the resource extraction system 10. The GUI element 220 includes awindow 222 that may display the waveform 224 of a signal correspondingto a given sensor 34. With respect to the device being monitored by thesensor 34, the window 226 displays various parameters, includingtemperature (field 228), pressure (field 230), device position (field232), as well as the velocity of the device when moving (field 234).

The GUI element 220 also includes indicators 236 and 238. Indicator 236is a status indicator, which may be configured to indicate if themonitored device is moving. For example, a device that is moving orbeing actuated may cause the indicator to display a particular color(e.g., green) while a device that is not moving or being actuated maycause the indicator to display another color (e.g., red). The indicator238 is an alarm condition indicator. For instance, if an alarm conditionis detected, the indicator may display one color or, if no alarmcondition is present, the indicator may display another color. As can beappreciated, this visual alarm indicator may be provided in conjunctionwith an audible alarm indicator (e.g., by a speaker or other suitablesound emitting device) connected to the workstation. Further, it shouldbe understood that the ranging system 36 may be configured to monitordata from multiple sensors monitoring various devices within the system.As such, each sensor may have associated with it a respective GUIelement 220 for displaying such information.

The ultrasonic position sensing system and techniques described hereinmay provide position information that is substantially as accurate asposition information obtained using other existing solutions, such asposition monitoring using LVDTs or other electromechanical positionsensors. However, as discussed above, the ultrasonic position sensingsystem integrates much more easily with existing subsea components anddoes not require substantial and complex redesign of existing equipment.Further, as the ultrasonic position sensors 34 described herein aregenerally not subject to common-mode failure mechanisms, as is the casewith some electromechanical position sensors, the position informationobtained by the ultrasonic position sensing system may better maintainits accuracy over time.

The position information obtained using the presently describedultrasonic position sensing techniques may also provide for some degreeof condition monitoring. For instance, linearly actuated devices mayhave an expected operational wear profile, which describes how thedevices are expected to behave as they gradually wear over time. Byhaving access to accurate position information obtained using ultrasonicposition sensors 34, an operator may monitor the condition of suchlinear moving devices over time. For instance, if the distance traveledby a ram of a blowout preventer that has been in operation for a givenamount of time in response to a certain amount of actuation pressurefalls within an expected range, it may be concluded that the blowoutpreventer is functioning normally in accordance with its wear profile.However, a distance traveled in response to the same actuation pressurethat is less than or greater than the expected range may signal that theblowout preventer may need to be serviced or replaced.

While the examples described above have focused on the use of anultrasonic position sensor for monitoring the position of a ram of ablowout preventer, it should be appreciated the above-describedtechniques may be applicable to generally any device or component of asystem that moves, such as in response to actuation. For example, in thecontext of the oilfield industry, other types of components havinglinearly actuated devices that may be monitored using the ultrasonicranging techniques described herein include blowout preventer gatevalves, wellhead connectors, a lower marine riser package connector,blowout preventer choke and kill valves and connecters, subsea treevalves, manifold valves, process separation valves, process compressionvalves, and pressure control valves, to name but a few. Additionally, asdiscussed above, components that move non-linearly may also be monitoredusing the position sensing techniques described above.

FIGS. 17 and 18 illustrate another embodiment of an ultrasonic positionsensing device, referred to here by reference number 250, which may beused for position monitoring in a subsea device, such as the ram-typeblowout preventer shown in FIG. 18. Components of the blowout preventerthat have already been described above with reference to FIGS. 3 to 7are labeled with like reference numbers. Here, rather than including arecess 108 and an opening 118 for wiring, the sensor body 110 may extendthrough the entire length of the head 60, as best shown in FIG. 18.Thus, in the present embodiment, what was previously a recess 108 inFIG. 7 has been extended all the way through the head 60 to form anopening therein. This opening 108 may include threads for engagingcorresponding threads 252 on the sensor body 110. Thus, the sensor 250may be installed in the opening 108 by rotating the body 110 within theopening 108 until the threads engage. In this embodiment, the sensorhousing 110 may be formed using an austenitic nickel-chromium-basedsuperalloy, such as Inconel 718, available from Special MetalsCorporation of New Hartford, N.Y.

As shown best in FIG. 17, the sensor may also include one or moreo-rings 258 disposed circumferentially about the body 250 between thewindow 116 and the threads 252. The end of the sensor 250 that protrudesfrom the outside of the head 60 when installed may include a connector254. In the illustrated embodiment, the connector 254 may be directedperpendicularly away from the sensor body 110 with respect to alongitudinal axis 256 of the sensor 250. By way of example only, theconnector 254 may be a model of a Dry-Mate Submersible Connector,available from Teledyne Technologies Inc. of Thousand Oaks, Calif.Accordingly, wiring for connecting the sensor 250 to the ranging logic36 may be connected to the sensor 250 via the connector 254. Thisembodiment of the sensor 250 is an example of one in which the sensor250 may be installed from the outside of the blowout preventer 32, asmentioned above with reference to FIG. 6.

While the aspects of the present disclosure may be susceptible tovarious modifications and alternative forms, specific embodiments havebeen shown by way of example in the drawings and have been described indetail herein. But it should be understood that the invention is notintended to be limited to the particular forms disclosed. Rather, theinvention is to cover all modifications, equivalents, and alternativesfalling within the spirit and scope of the invention as defined by thefollowing appended claims.

The invention claimed is:
 1. A position sensor comprising: a sensorhousing configured to be installed on a component having at least onedevice being monitored by the position sensor; and a transducer modulehaving a piezoelectric material, a window comprising a plastic material,and a temperature sensing device, wherein the transducer module isconfigured to be disposed within the sensor housing, to transmit anultrasonic signal through the window and through a fluid medium toward asurface of the device being monitored, to receive a reflection of theultrasonic signal from the surface of the device, and to transmit anelectrical signal corresponding to the ultrasonic signal to processinglogic configured to calculate the velocity of the ultrasonic signal as afunction of pressure and temperature and to use the calculated velocityto calculate the distance between the position sensor and the device asa function of the velocity of the ultrasonic signal.
 2. The positionsensor of claim 1, comprising a connector coupled to the sensor housing,wherein the connector is configured to electronically couple thetransducer module to the processing logic.
 3. The position sensor ofclaim 2, wherein the temperature sensing device is configured todetermine the temperature of the fluid medium and to provide thetemperature to the processing logic via the connector.
 4. The positionsensor of claim 1, wherein the plastic material comprises at least oneof a polyetherimide, organic polymer thermoplastic, or a polyimide-basedplastic.
 5. The position sensor of claim 1, wherein the piezoelectricmaterial comprises lead zirconate titanate.
 6. The position sensor ofclaim 1, comprising an alumina wear plate interposed between thepiezoelectric material and the window.
 7. The position sensor of claim1, wherein the transducer module comprises a plastic casing in which thepiezoelectric material is disposed, and wherein the plastic casing isconfigured to be enclosed within the sensor housing.
 8. The positionsensor of claim 1, wherein the sensor housing comprises a metal, alloy,or super-alloy, configured to allow the position sensor to operate atpressures of between 14 pounds per square inch (PSI) to 14,000 PSI.
 9. Amethod for determining the position of a component configured formovement comprising: using a first ultrasonic position sensor totransmit a first ultrasonic signal through a fluid medium to a referencepoint, wherein a first distance between the first ultrasonic positionsensor and the reference point is generally constant; measuring theround-trip transit time of the first ultrasonic signal between the firstultrasonic position sensor and the reference point; determining theacoustic velocity of the first ultrasonic signal through the fluidmedium based upon the first distance and the round-trip transit time;using a second ultrasonic position sensor to transmit a secondultrasonic signal through the fluid medium to a surface of thecomponent; measuring the round-trip transit time of the secondultrasonic signal between the second ultrasonic position sensor and thesurface of the component; and determining a second distance between thesecond ultrasonic position sensor and the surface of the component basedupon the measured round-trip transit time of the second ultrasonicsignal and the acoustic velocity of the first ultrasonic signal, thesecond distance being indicative of the location of the componentrelative to the position of the second ultrasonic position sensor. 10.The method of claim 9, wherein the first ultrasonic position sensor andthe second ultrasonic position sensor are oriented perpendicularly withrespect to each other.
 11. The method of claim 9, wherein the referencepoint comprises another surface of the component, wherein the distancebetween the other surface of the component and the first ultrasonicsensor remains generally constant even when the component is moving. 12.The method of claim 11, wherein the component comprises a piston,wherein the surface of the piston toward which the second ultrasonicsignal is transmitted is a flange of the piston and wherein the surfaceof the piston towards which the first ultrasonic signal is transmittedis a shaft of the piston.
 13. The method of claim 12, wherein the pistonis a component of a blowout preventer of a resource extraction system.